U.S. patent number 4,748,011 [Application Number 07/057,031] was granted by the patent office on 1988-05-31 for method and apparatus for sweetening natural gas.
Invention is credited to Thomas H. Baize.
United States Patent |
4,748,011 |
Baize |
May 31, 1988 |
Method and apparatus for sweetening natural gas
Abstract
A method and apparatus are disclosed for sweetening of natural
gas at the well head or at a common collection point from a number
of wells, where, in the usual collection system for natural gas,
the gas from one or more wells is collected through a collection
line or manifold and often subjected to conventional treatments for
dehydration and/or separation of petroleum condensates. A storage
tank for sweetening liquid, comprising a solution of a low
molecular weight aldehyde or ketone and water, methanol,
isopropanol, and an amine buffer or inhibitor may be added. The
resulting solution is connected by a conduit to a pump which is
connected to an injector/atomizer extending laterally into the pipe
at a point or points from the well head to sales line. The
injector/atomizer sprays the sweetening liquid into the flowing
stream of gas in an amount sufficient to react with the hydrogen
sulfide to convert it into a hydroxymethyl (or other lower
molecular weight hydroxyalkyl) mercaptan and other sulfur bearing
compounds. The sweetening reaction takes place in-line without the
need for a holding tank or reaction vessel. The reaction is
complete and effective to completely sweeten a sour gas system.
Inventors: |
Baize; Thomas H. (Missouri
City, TX) |
Family
ID: |
22008071 |
Appl.
No.: |
07/057,031 |
Filed: |
June 2, 1987 |
Related U.S. Patent Documents
|
|
|
|
|
|
|
Application
Number |
Filing Date |
Patent Number |
Issue Date |
|
|
513319 |
Jul 13, 1983 |
|
|
|
|
Current U.S.
Class: |
423/228; 423/234;
95/235 |
Current CPC
Class: |
B01D
53/1456 (20130101); B01D 53/1493 (20130101); C07C
7/14875 (20130101); C07C 7/14875 (20130101); C07C
9/04 (20130101) |
Current International
Class: |
B01D
53/14 (20060101); C07C 7/148 (20060101); C07C
7/00 (20060101); B01D 053/14 () |
Field of
Search: |
;55/32,68,73,171-177
;423/226,228,234 |
References Cited
[Referenced By]
U.S. Patent Documents
Primary Examiner: Hart; Charles
Attorney, Agent or Firm: Mosely; Neal J.
Claims
I claim:
1. In a method of collection and separation of natural gas wherein
a sour natural gas from a well head is passed through a knock out
separator to remove free liquids, the treated gas is expanded
through a choke into a low temperature separator to cool the gas
sufficiently to condense water or hydrocarbon condensate, or water
and hydrocarbon condensate therein and to collect dry natural gas
overhead therein, the steps which comprise
removing dry gas continuously from said low temperature separator
through a transfer line to a sales gas flow line,
providing an injector-valve sealed in the wall of one of the flow
lines in the system comprising a valve body with an atomizer nozzle
extending into the stream of flowing dry natural gas, a check valve
preventing back flow from the flow line, a shut off valve, and an
inlet,
providing a pump having an inlet and having an outlet connected to
said valve inlet,
providing a storage tank connected to said pump inlet,
providing a sweetening solution in said tank consisting essentially
of 10-50 % wt. a low molecular weight aldehyde, or a low molecular
weight ketone; 20-80% water; 10-50% methanol; 1-25% amine
inhibitor; 0-5% sodium hydroxide or potassium hydroxide and 2-5%
isopropanol, where the percentages total one hundred, and the pH is
6.0-14 and
operating said pump to supply said sweetening solution continuously
at a rate sufficient to react continuously with hydrogen sulfide to
sweeten the natural gas.
2. A method according to claim 1 in which
said injector-valve comprises a tubular valve body threaded in the
wall of said flow line having an inlet opening at the top and an
atomizer nozzle at the end inside said flow line,
a valve seat inside said valve body and a ball check valve
positioned to close against said valve seat upon back flow
therethrough,
a second valve seat in said valve body, and
a hand-operated valve member movable into engagement with said
second valve seat to shut off flow during installation and removal
of said pump and solution tank.
3. A method according to claim 1 in which
said aldehyde or ketone is formaldehyde, acetaldehyde,
propionaldehyde, butyraldehyde, acetone, methyl ethyl ketone,
diethyl ketone, or methyl propyl ketone, and
said amine inhibitors are water soluble oxidation and corrosion
inhibitors comprising alkyl pyridines, quaternary ammonium salts,
monomethylamine, monoethylamine, monopropylamine, dimethylamine,
diethylamine, dipropylamine, trimethylamine, triethylamine,
tripropylamine, monomethanolamine, monoethanolamine,
monopropanolamine, dimethanolamine, diethanolamine,
dipropanolamine, trimethanolamine, triethanolamine,
tripropanolamine, dimethyl ethanol amine, methyl diethanol amine,
dimethyl amino ethanol, imidazoline or morpholine.
4. A method according to claim 1 in which
said sweetening solution is introduced typically in the amount of
200-300 ppm thereof per 100 ppm of hydrogen sulfide in the flowing
natural gas stream gas stream to reduce the hydrogen sulfide level
to 4.0 ppm or less. Lower or higher concentrations of hydrogen
sulfide are similarly treated.
5. In an apparatus for collection and separation of natural gas
which comprises
means for collecting a sour natural gas from a well head,
a knock out separator connected to receive said sour natural gas
from said collection means and operable to remove entrained liquid
droplets therefrom,
a low temperature separator,
a choke connected to receive said sour natural gas from said knock
out separator and discharging into said low temperature separator
to reduce the gas pressure to cool the gas sufficiently to condense
water or hydrocarbon condensate, or water and hydrocarbon
condensate therein and to collect dry natural gas overhead therein,
and
a sales gas flow line connected to remove dry natural gas
continuously from said low temperature separator,
the combination of sweetening apparatus therewith comprising
an injector-valve sealed in the wall of said flow line comprising a
valve body with an atomizer nozzle extending into the stream of
flowing dry natural gas, a check valve preventing back flow from
the flow line, a shut off valve, and an inlet,
a pump having an inlet and having an outlet connected to said valve
inlet,
a storage tank connected to said pump inlet, and
a sweetening solution in said tank consisting essentially of 10-50%
wt. of a low molecular weight aldehyde, or a low molecular weight
ketone; 20-80% water; 10-50% methanol; 1-25% amine inhibitor; 0-5%
sodium hydroxide or potassium hydroxide and 2-5% isopropanol, where
the percentages total one hundred, and at a pH of 6.8-14,
whereby said pump may be operated to supply said sweetening
solution continuously at a rate sufficient to react continuously
with the hydrogen sulfide.
6. An apparatus according to claim 5 in which
said injector-valve comprises a tubular valve body threaded in the
wall of said flow line having an inlet opening at the top and an
atomizer nozzle at the end inside said flow line,
a valve seat inside said valve body and a ball check valve
positioned to close against said valve seat upon back flow
therethrough,
a second valve seat in said valve body, and
a hand-operated valve member movable into engagement with said
second valve seat to shut off flow during installation and removal
of said pump and solution tank.
7. A apparatus according to claim 5 in which
said aldehyde or ketone is formaldehyde, acetaldehyde,
propionaldehyde, butyraldehyde, acetone, methyl ethyl ketone,
diethyl ketone, or methyl propyl ketone, and
said amine inhibitors are water soluble oxidation and corrosion
inhibitors comprising alkyl pyridines, quaternary ammonium salts,
monomethylamine, monoethylamine, monopropylamine, dimethylamine,
diethylamine, dipropylamine, trimethylamine, triethylamine,
tripropylamine, monomethanolamine, monoethanolamine,
monopropanolamine, dimethanolamine, diethanolamine,
dipropanolamine, trimethanolamine, triethanolamine,
tripropanolamine, dimethyl ethanol amine, methyl diethanol amine,
dimethyl amino ethanol, imidazoline or morpholine.
Description
BACKGROUND OF THE INVENTION
1. Field of the Invention
This invention relates to improvements in the sweetening of natural
gas and more particularly to a method and apparatus for sweetening
natural gas at the well head or a collection point in the
field.
2. Brief Description of the Prior Art
The production of natural gas often requires the separation or
removal of various contaminants from the gas before it can be sent
on for use. Natural gas often includes a substantial amount of
entrained water and vaporized liquid hydrocarbons, usually the more
volatile ones. Consequently, the gas is subjected to treatment for
separation of these components.
Natural gas may also contain gaseous impurities such as carbon
dioxide and hydrogen sulfide which are acids in aqueous solution
and thus corrosive. Hydrogen sulfide-containing gas is also highly
toxic and malodorous and is referred to as "sour" gas. In fact,
hydrogen sulfide is more toxic than HCN and presents the problem
that it is highly malodorous at extremely low concentrations and
tends to anesthetize the olefactory nerves with the result that a
toxic exposure may not be recognized until it is too late. The
removal or neutralization of hydrogen sulfide is therefore a matter
of necessity from a safety standpoint.
The removal of carbon dioxide is not always required but can
usually be removed by the other processes used to remove hydrogen
sulfide. In many processes of treatment, the chemicals used for
sweetening react with both carbon dioxide and hydrogen sulfide and
therefore the total amount of these impurities is used in
calculating the amount of treating chemicals needed.
In most procedures, the natural gas is first treated to remove
water vapor and to separate condensable hydrocarbons or
"condensate". The partial expansion of the gas through a choke to a
lower pressure is effective to cool the gas sufficiently to remove
both water and volatile hydrocarbons by condensing them from the
gas stream. Often, there is a material added, such as ethylene
glycol which will absorb or hydrate with the water to condense more
readily from the gas stream. The expansion through the choke and
consequent cooling is usually sufficient to condense the volatile
liquid hydrocarbons which are recovered for use as solvents or
fuel, i.e. casing head gasoline.
The major process for removal of acid constituents from natural gas
is one using an alkanolamine, such as monoethanolamine (MEA),
diethanolamine (DEA), and/or triethanolamine (TEA). Treatment with
alkanolamines involves circulating natural gas upward through a
treatment tower to contact the alkanolamines. The acid gases react
with the alkanolamines to form either a hydrosulfite or a carbonate
of an alkanolamine. The alkanolamines admixed with the reaction
products are conducted to a stripping still where the alkanolamines
are removed and returned to the treatment column. The reaction
products are then conducted to a reactor where they are heated
sufficiently to reverse the process and regenerate the
alkanolamines and release the acid gases which may be flared to
convert hydrogen sulfide to sulfur dioxide, or further reacted to a
form for solid disposal, or sent to a sulfur manufacturing
plant.
There are several variations on the alkanolamine desulfurization
process in use. One such process is the Shell Sulfinol process
(licensed by Shell) which utilizes a mixed solvent. The Sulfinol
solvent is an admixture of sulfolane, water and di-isopropanolamine
(DIPA). Another process of this type utilizes a mixture of
alkanolamines with ethylene glycol and water. This process combines
the removal of water vapor, carbon dioxide and hydrogen
sulfide.
Another process for removal of hydrogen sulfide, uses a solid-gas
chemical reaction. An iron sponge, consisting of a hydrated iron
oxide on an inert support, is treated with the sour gas where the
iron is converted to the sulfide. The iron sulfide can be
reoxidized to the oxide with release of elemental sulfur.
Some physical processes are used for removal of carbon dioxide and
hydrogen sulfide. Molecular sieves, i.e. zeolites and other
materials having a pore size of molecular dimensions, which are
specific in pore size for removal of carbon dioxide and hydrogen
sulfide are used in the form of a bed through which the sour gas is
passed. The bed is periodically regenerated by stripping with an
inert gas. This process has the disadvantage present in most
desulfurizing processes in that the separated hydrogen sulfide or
sulfur dioxide must be disposed of in the field.
All of the above desulfurization process have the disadvantage that
reaction vessels, strippers, stills, separators and the like must
be provided, which have a high capital cost. Also, these processes
have the disadvantage that the current laws dealing with air
pollution make it difficult to dispose of the separated hydrogen
sulfide or sulfur dioxide under field conditions.
The present invention involves the use of inexpensive equipment and
reagents for sweetening which avoid the problem of disposal of
separated hydrogen sulfide or sulfur dioxide under field
conditions.
SUMMARY OF THE INVENTION
One of the objects of this invention is to provide a new and
improved method and apparatus for sweetening sour natural gas at
the well head or during collection.
Another object of this invention is to provide a method for
sweetening sour natural gas at the well head or during collection
which utilizes simple and inexpensive equipment.
Another object of this invention is to provide a system of simple
and inexpensive equipment for injection of chemicals for sweetening
sour natural gas at the well head or during collection under
flowing conditions.
Still another object of this invention is to provide a method for
sweetening sour natural gas at the well head or during collection
which utilizes simple and inexpensive equipment for atomizing a
sweetening solution into a flowing stream of natural gas.
Still another object of this invention is to provide a method for
sweetening sour natural gas at the well head or during collection
which utilizes simple and inexpensive equipment for atomizing a
sweetening solution into a flowing stream of natural gas after
separation of particulate impurities and removal of water and
volatile hydrocarbons.
Yet another object of this invention is to provide a system of
simple and inexpensive equipment for injecting or atomizing a
chemical solution for sweetening sour natural gas at the well head
or during collection under flowing conditions.
Yet another object of this invention is to provide a method for
sweetening sour natural gas at the well head or during collection
by injecting or atomizing a sweetening solution, comprising a
mixture of a low molecular weight aldehyde or ketone and water,
optionally including methanol, isopropanol and a buffer or
inhibitor, singularly or in combination into a flowing stream of
natural gas, and which utilizes simple and inexpensive
equipment.
Another object of this invention is to provide a method for
sweetening sour natural gas at the well head or during collection
by injecting or atomizing a sweetening solution, comprising a
solution of formaldehyde in methanol, isopropanol and a buffer or
inhibitor, into a flowing stream of natural gas, and which utilizes
simple and inexpensive equipment.
Other objects of this invention will become apparent from time to
time throughout the specification and claims as hereinafter
related.
These objects, and other objects of the invention are accomplished
by the disclosed method and apparatus for sweetening of natural gas
at the well head or at a common collection point from a number of
wells, where, in the usual collection system for natural gas, the
gas from one or more wells is collected through a collection line
or manifold and subjected to a conventional treatment for
dehydration and separation of petroleum condensate. A storage tank
or barrel for a sweetening liquid, comprising a solution of a low
molecular weight aldehyde or ketone and water with possibly
methanol, and/or isopropanol, and/or an amine buffer or inhibitor,
is connected by a conduit to a pump and then to an
injector/atomizer extending laterally into the pipe at a point or
points from the well head to sales. The injector/atomizer sprays
the sweetening liquid into the flowing stream of gas in an amount
sufficient to react with the hydrogen sulfide to convert it into a
hydroxymethyl (or other lower molecular weight hydroxyalkyl)
mercaptan and/or other sulfur compounds. The sweetening reaction
takes place in-line without the need for a holding tank or reaction
vessel. The reaction is complete and effective to completely
sweeten the sour gas.
BRIEF DESCRIPTION OF THE DRAWINGS
FIG. 1 is a schematic flow diagram illustrating a prior art system
of apparatus for collection of natural gas and separation of
condensate therefrom.
FIG. 2 is a schematic flow diagram illustrating a prior art system
of apparatus for collection of natural gas and separation of
condensate and water therefrom, including glycol injection and
condensate stabilization.
FIG. 3 is a partially schematic diagram illustrating the injection
of sweetening solution into the transfer gas line at any point or
points from well head to sales in systems such as those shown in
FIGS. 1 and 2, or the like.
DESCRIPTION OF THE PREFERRED EMBODIMENTS
This invention is based on the discovery that sour natural gas may
be sweetened by injection of a sweetening solution into the
produced gas line from well head through collection and separation
systems. The sweetening solution is atomized into the flowing gas
stream and reacts with the hydrogen sulfide in line to meet
industry requirements. This sweetening method, and the apparatus
used to carry it out, can be used with any conventional, i.e.,
prior art, system of apparatus for collection of natural gas and
separation of condensate therefrom. The improved method and
apparatus will be described below for use in two prior art systems
of apparatus for collection of natural gas and separation of
condensate therefrom. The two systems illustrated are ones which
demonstrate the low temperature processes for separation of
condensate from natural gas, either with or without glycol
injection for inhibiting hydrate formation.
PRIOR ART SYSTEM FOR LOW TEMPERATURE SEPARATION OF NATURAL GAS FROM
LIQUID CONDENSATE
Referring to FIG. 1 of the drawings, there is shown a conventional,
prior art, system for collection of natural gas and separation of
liquid condensate therefrom.
Petroleum products are produced from a plurality of well heads 1
and collected through a collection manifold 2 as a mixture of
natural gas, crude oil, entrained liquid condensate, water vapor,
and often acid impurities, including carbon dioxide and hydrogen
sulfide. As previously noted, natural gas containing hydrogen
sulfide (sour gas) must be treated to remove hydrogen sulfide.
The petroleum mixture from manifold 2 passes through a separator S
where the crude oil is removed through side line 3 to storage,
transportation or further treatment. If the wells are producing
only gas, the separator S may be omitted from the collection and
treatment system. The gaseous portion of the well production,
consisting of natural gas, entrained volatile liquid hydrocarbons
(called "condensate"), and water vapor, is conducted by line 4
through a heater 5 to heat the mixture to provide heat in the
separatory process equipment.
Line 6 conducts the heated gas through a heat exchange coil 7 in a
low temperature separator 8 whose function will be described more
thoroughly below. Line 9 conducts high pressure gas mixture from
the separator 8 to the inlet side of a separator 10 known as a high
pressure liquid knock out for removal of easily condensed and
entrained liquids and vapors.
Line 11 conducts some condensed water and hydrocarbons (condensate)
to low temperature separator 8. Outlet line 12 conducts high
pressure gas to a choke 13 which is connected by line 14 to low
temperature separator 8. Low temperature separator 8 separates the
products into a bottom liquid layer of water, a top liquid layer of
condensate, and a top volume of natural gas, essentially free of
water and condensate.
Line 15 from the bottom of low temperature separator 8 conducts
separated water to disposal. Line 16 at the top of low temperature
separator 8 removes the separated natural gas for transportation to
point of sale, i.e., the "sales gas" line. A stand pipe 17 in low
temperature separator 8 removes condensed hydrocarbons (condensate)
and some dissolved natural gas to line 18 connected to a low
pressure separator 19. In the separator 19, the condensate is
removed through bottom line 20 and the small amount of natural gas
is removed through top line 21.
The system so far described contains the basic components for
collection of natural gas and separation of water and distillate
therefrom. The system, as shown, includes only one (the coil 7) of
the many heat exchangers used in such a system, and does not
include any means for desulfurization or sweetening or any means
for inhibiting hydrate formation in the gas stream.
In the system shown, the separator S may be a conventional vertical
oil and gas separator or the like. Heater 5 may burn part of the
collected gas as fuel, or may use external fuel or even be
electrically heated. The heated gas mixture passing through heat
exchanger 7 keeps the water layer in low temperature separator 8
from freezing. High pressure liquid knock out is typically a double
tube horizontal separator of conventional design with baffles which
stop entrained liquid drops and cause them to drop into the lower
part of the equipment to be conducted to the low temperature
separator 8.
The gas mixture from high pressure liquid knock out 10 is
substantially reduced in pressure by passing through choke 13 which
cools the gas mixture sufficiently to cause the water and liquid
hydrocarbons to condense out into separate layers in low
temperature separator 8 where the natural gas, free or water and
condensate, is removed to the sales gas line 16. The sales gas may
still contain acid impurities such as hydrogen sulfide and/or
carbon dioxide which must be removed. As previously noted these
impurities may be removed by auxiliary treating apparatus which is
very expensive.
PRIOR ART SYSTEM FOR LOW TEMPERATURE SEPARATION OF NATURAL GAS FROM
LIQUID CONDENSATE INCLUDING GLYCOL INJECTION
Referring to FIG. 2 of the drawings, there is shown a conventional,
prior art, system for collection of natural gas and separation of
liquid condensate therefrom, including a system for glycol
injection to assist in removal of water vapor and to prevent the
formation of hydrate particles.
Petroleum products are produced from a plurality of well heads 30
and collected through a collection manifold 31 as a mixture of
natural gas, crude oil, entrained liquid condensate, water vapor,
and often acid impurities, including carbon dioxide and hydrogen
sulfide. As previously noted, natural gas containing hydrogen
sulfide (sour gas) must be treated to remove hydrogen sulfide. This
is substantially as in FIG. 1.
The petroleum mixture from manifold 31 is conducted to separator S
where the crude oil is removed through a side line 32 to storage,
transportation or further treatment. If the wells are producing
only gas, the separator S may be omitted from the collection and
treatment system. The gaseous portion of the well production,
consisting of natural gas, entrained volatile liquid hydrocarbons
(called "condensate"), and water vapor, is conducted by line 33 to
the inlet side of a separator 34 known as a free water liquid knock
out for removal of water through line 35 for disposal.
Line 36 conducts high pressure gas to a choke 37 which is connected
by line 38 to low temperature separator 39. Dry ethylene glycol is
introduced into the gas stream by injector 40 ahead of choke 37.
The glycol combines with the water vapor to inhibit formation of
hydrates in the gas. This eliminates the need for the coil 7 in
Fig. which was required to keep solid hydrates from forming. The
glycol-water mixture separates from the natural gas in separator 39
and the glycol is subsequently dried and recycled.
Low temperature separator 39 separates the products into a layer of
water-glycol and condensate, and a top volume of natural gas,
essentially free of water and condensate. Line 41 at the top of low
temperature separator 39 removes the separated natural gas for
transportation to point of sale, i.e., the "sales gas" line.
The bottom outlet of low temperature separator 39 removes condensed
hydrocarbons (condensate) and some dissolved natural gas to line 42
connected to a stabilizer (separator) column 43 where light
fractions are removed overhead and collected through line 44. A
mixture of wet glycol and condensate is removed through line 45 at
the bottom of stabilizer 43 to a glycol-condensate separator 46. An
overhead line 47 from separator 46 removes the condensate to
storage.
Bottom line 48 from separator 46 conducts wet glycol to a drier or
boiler 49 where water is removed through overhead line 50. Dried
glycol is removed from boiler 49 through line 51 to the inlet side
of filter 52. Make-up glycol is added, as needed, at addition port
53. Filter 52 is connected by line 54 to the inlet of pump 55, the
outlet of which is connected by line 56 to glycol injector 40 as
described above.
As was described in connection with FIG. 1, the system so far
described contains the basic components for collection of natural
gas and separation of water and distillate therefrom. The system,
as shown, includes none of the many heat exchangers used in such a
system, and does not include any means for desulfurization or
sweetening or any means for inhibiting hydrate formation in the gas
stream.
In the system shown, the separator S may be a conventional vertical
oil and gas separator or the like. Free water knock out 34 is
typically a double tube horizontal separator of conventional design
with baffles which stop entrained water drops and cause them to
drop into the lower part of the equipment to be conducted to water
disposal.
The gas mixture from high pressure free water knock out 34 is mixed
with glycol and then substantially reduced in pressure by passing
through choke 37 which cools the gas mixture sufficiently to cause
the water-glycol and liquid hydrocarbons to condense out in low
temperature separator 39 where the natural gas, free or water and
condensate, is removed to sales gas line 41. Sales gas may still
contain acid impurities such as hydrogen sulfide and/or carbon
dioxide which must be removed. As previously noted these impurities
may be removed by auxiliary treating apparatus which is very
expensive.
A PREFERRED EMBODIMENT OF THE METHOD AND APPARATUS FOR SWEETENING
NATURAL GAS FLOWING IN THE SALES GAS LINE FROM THE GAS/CONDENSATE
SEPARATION SYSTEM
In FIG. 3, there is shown a system of apparatus for introduction of
a sweetening liquid into the flowing natural gas stream in the
transfer gas line 16 (in FIG. 1) or at any point or points from
well head or well heads to gas to sales 41.
The sweetening liquid is a solution comprising 10-50 % wt. of
formaldehyde or other low molecular weight aldehyde, such as
acetaldehyde, propionaldehyde, butyraldehyde, or the like, or a low
molecular weight ketone, such as acetone, methyl ethyl ketone,
diethyl ketone, methyl propyl ketone, or the like; 20-80% water;
10-50% methanol; 1-25% amine inhibitor; 0-5% sodium hydroxide or
potassium hydroxide, and 2-5% isopropanol, where the percentage
total one hundred, and at a pH 6.8-14. The amine inhibitors are
water soluble oxidation and corrosion inhibitors including alkyl
pyridines, quaternary ammonium salts, alkylamines, such as mono-,
di-, and/or tri- methyl, ethyl, or propyl amines, alkanolamines,
such as mono methanol, ethanol, or propanol amines, di- methanol,
ethanol, or propanol amines, tri- methanol, ethanol, or propanol
amines, dimethyl ethanol amine, methyl diethanol amine, dimethyl
amino ethanol, or morpholine.
In FIG. 3, the system of apparatus comprises a drum or other
storage tank 60 for the sweetening solution described above. Tank
60 is connected by line 61 to pump 62 which is in turn connected by
line 63 to valve-injector 64 threaded into the wall of line 16 or
other suitable point in the flow diagram shown in FIG. 2. Valve 64
has a body 65 with a spray nozzle or atomizer 66 at its end for
atomizing the sweetening solution into the stream of flowing
natural gas. Valve body 65 may have a check valve 67 permitting
flow only into the gas line of FIG. 2 or FIG. 3. A shut off valve
68 operated by handle 69 may be present for shutting the valve and
injector off during hook up or recharging the solution tank.
In operation, tank 60 is filled with a sweetening solution of 30%
wt. formaldehyde; 30% water; 30% methanol; 5% imidazoline
inhibitor; 2.0% sodium hydroxide and 3% isopropanol.
Shut off valve 68 is opened by handle 69 and pump 62 pumps the
sweetening solution through injector 66 in a spray into point or
points in the line of gas flow is the system as shown in FIGS. 2
and 3. The flowing gas is analyzed from time to time to determine
the hydrogen sulfide content, and the flow of sweetening solution
is adjusted to add an amount just sufficient for the reaction to
convert the hydrogen sulfide to the hydroxymethyl mercaptan and
other sulfur bearing compounds. Typically, 200-300 ppm of the
sweetening solution per 100 ppm of hydrogen sulfide in the flowing
natural gas stream injected into the flowing natural gas stream is
effective to reduce the hydrogen sulfide level to 4.0 ppm or less,
which meets both industry and environmental standards. Lower or
higher concentrations of hydrogen sulfide are similarly
treated.
While this invention has been described fully and completely with
special emphasis on a few preferred embodiments, it should be
understood that, within the scope of the appended claims, the
invention may be practiced otherwise than as specifically described
herein.
* * * * *